In seismic exploration, seismic data is acquired along lines that consist of geophone arrays onshore or hydrophone streamer traverses offshore. Geophones and hydrophones act as sensors to receive energy that is transmitted into the ground and reflected back to the surface from subsurface rock interfaces. Energy is usually provided onshore by Vibroseis.RTM. vehicles which transmit pulses by shaking the ground at pre-determined intervals and frequencies on the surface. Offshore, airgun sources are usually used. Subtle changes in the energy returned to surface often reflect variations in the stratigraphic, structural and fluid contents of the reservoirs.
In performing three-dimensional (3-D) seismic exploration, the principle is similar, however, lines and arrays are more closely spaced to provide more detailed sub-surface coverage. With this high density coverage, extremely large volumes of digital data need to be recorded, stored and processed before final interpretation can be made. Processing requires extensive computer resources and complex software to enhance the signal received from the subsurface and to mute accompanying noise which masks the signal.
Once the data is processed, geophysical staff compile and interpret the 3-D seismic information in the form of a 3-D data cube (See FIG. 1) which effectively represents a display of subsurface features. Using this data cube, information can be displayed in various forms. Horizontal time slice maps can be made at selected depths (See FIG. 2). Using a computer workstation an interpreter can also slice through the field to investigate reservoir issues at different seismic horizons. Vertical slices or sections can also be made in any direction using seismic or well data. Time maps can be converted to depth to provide a structural interpretation at a specific level.
Seismic data has been traditionally acquired and processed for the purpose of imaging seismic reflections. However, changes in stratigraphy are often difficult to detect on traditional seismic displays due to the limited amount of information that stratigraphic features present in a cross-section view. Although such views provide an opportunity to see a much larger portion of these features, it is difficult to identify fault surfaces within a 3-D volume where no fault reflections have been recorded.
Coherence and semblence (a measure of multichannel coherence) are two measures of seismic trace similarity or dissimilarity. As two seismic traces increase in coherence, the more they are alike. Assigning a coherence measure on a scale from zero to one, "0" indicates the greatest lack of similarity, while a value of "1" indicates total or complete similarity (i.e., two identical traces). Coherence for more than two traces may be defined in a similar way.
One method for computing coherence was disclosed in a U.S. patent application (now U.S. Pat. No. 5,563,949) by Bahorich and Farmer (assigned to Amoco Corporation) having a Ser. No. of 08/353,934 and a filing date of Dec. 12, 1994. A method for computing semblance was disclosed in a U.S. patent application by Marfurt et. al. (assigned to Amoco Corporation) having an application Ser. No. of 60/005,032 and a filing date of Oct. 6, 1995. The Marfurt et al. invention included a brute force search over candidate dips and azimuths.
As good as both methods have proved to be, they have some limitations. Improved resolution and computational speed are always desirable.